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The aim of this study is to assess the economic potentials of power and hydrogen generation via solar and wind energy resources at locations in Northern Germany and California, both of these (geographical) regions being pioneers in terms of a sustainable energy transition. Based on extensive research and electrolyzer manufacturer interviews, green hydrogen generation plants are modeled in a MATLAB® environment. All relevant inputs and outputs of the systems studied (wind power plants, photovoltaic power plants, and polymer electrolyte membrane electrolyzers, among others) are considered for different locations and framework conditions. In contrast to the existing literature, special attention is paid to the part-load behavior of electrolysis systems, which becomes particularly relevant in their interplay with volatile renewables. Metrics such as the levelized costs of electricity (LCOE) of the wind and photovoltaic power plants and the resulting levelized costs of hydrogen (LCOHy) are determined. With the help of the developed model, dimensioning of a whole system's components can be determined for different locations. A case study is conducted for a Northern German site and another one for a site in the Californian Mojave Desert. Both the optimal dimensioning of the renewable energy plants and the ratio of installed wind and photovoltaic power plant capacity are strongly location-dependent. In Northern Germany, for example, lower LCOHy can be generated at higher wind power plant capacity shares and, in the Mojave Desert, be produced at higher photovoltaic power plant capacity shares. In general, with larger plants and correspondingly larger polymer electrolyte membrane electrolyzers, LCOHy are lower due to scaling effects. Following this dimensioning recommendation, the LCOHy vary between 4.5 €/kg and 5.2 €/kg in the Northern German case study and between 4.6 US$/kg and 5.3 US$/kg in the Californian one. With costs of 1–2 €/kg, gray hydrogen is still economically superior. • Hydrogen production is modeled based on electrolyzers, wind and PV power plants. • Due to the volatile power supply, a focus is on part-load behavior of electrolyzers. • The optimal sizing of the system components is determined for different locations. • Two case studies are conducted, for Northern Germany and the Mojave Desert, CA. • Levelized costs of hydrogen are found to vary between 4.5 and 5.2 €/kg (4.6–5.3 US$/kg). [ABSTRACT FROM AUTHOR]

Guarantees of Origin (GOs) were introduced in order to enhance transparency about the origin of green electricity produced in Europe, and to deliberately empower end-consumers to participate in the sustainable energy transition. The separation of electricity and the GO trade has resulted in a prosperous GO market that, however, has been characterized by non-transparency and opportunistic behavior. Historic price development has been opaque and can therefore not be used to forecast future GO prices. This paper, firstly, provides a thorough overview of the European GO market and an analysis of the historic price development; secondly, it proposes a model, the first of its kind, for determining future price developments of European GOs for different renewable energy technologies in different countries up to 2040. For household consumers, GO price determination is based on willingness-to-pay estimates from the literature, whereas for non-household consumers, the model introduces a novel approach to determine the willingness to pay for green electricity. Four different scenarios are considered (Status Quo, Sustainable Development, Full Harmonization, and Ideal Development) and annual GO data are used. The findings indicate that GO prices can be expected to increase on average in the next years, with prices ranging from 1.77 to 3.36 EUR/MWh in 2040. Sensitivity analysis shows that 'WTP percentages' have the highest influence on GO prices. It can be concluded that future GO prices will remain challenging to predict, even with the support of sophisticated models, due to the expected supply and demand-driven market growth affecting the market equilibrium prices for different GOs in different countries. [ABSTRACT FROM AUTHOR]

State-induced components constitute the major share of electricity prices for consumers and are generally charged at a fixed rate. We analyze the benefits of charging state-induced price components at time-varying rates instead, especially with regard to the integration of variable renewable energy (VRE) sources and to decarbonization. For this purpose, we apply a detailed power market model that puts particular emphasis on electricity demand and how it is sensitive to prices. For a quantitative case study, the model is parametrized to represent a German energy system with an 85% share of renewables in its power generation. We find that dynamization has a reducing effect on integration costs of VRE, ranging from 0.3 to 3.4 €/MWh. Furthermore, strong distributional effects in favor of flexible consumers can be observed. [ABSTRACT FROM AUTHOR]

This paper presents an econometric analysis of curtailment costs of renewable energy sources (RES) in Germany. The study aims at explaining and quantifying the regional variability of RES curtailment, which is a measure to relieve grid overstress by temporarily disconnecting RES from the electricity grid. We apply a Heckit sample selection model, which corrects bias from non-randomly selected samples. The selection equation estimates the probability of occurrence of RES curtailment in a region. The outcome equation corrects for cross-sectional dependence and quantifies the effect of RES on curtailment costs. The results show that wind energy systems connected to the distribution grid increase RES curtailment costs by 0.7% per MW (or 0.2% per GWh) in subregions that have experienced RES curtailment over the period 2015-2017. The implication of this finding is that policymakers should set price signals for renewables that consider the regional grid overstress, in order to mitigate the cost burden on consumers due to excess generation from RES. [ABSTRACT FROM AUTHOR]

We estimate direct and indirect energy rebound effects for a wide variety of goods and services in Germany. To this end, we employ a linearized approximation of the popular Almost Ideal Demand System (AIDS) approach suggested by Deaton and Muellbauer (1980). Excluding measures of energy efficiency when estimating rebound can lead to biased results. We compensate for this shortcoming of previous research by explicitly accounting for energy efficiency in our estimations. Using data for Germany from 1970 to 2017, we find moderate direct and significant indirect rebound effects for different energy carriers across four model specifications. The size of the rebound effect proves to be sensitive to the expenditure shares used for the calculations, which in some cases leads to negative overall rebound estimates. [ABSTRACT FROM AUTHOR]

• Commercial drivers are more satisfied with electric than with conventional vehicles. • Electric vehicles lead to perceived efficiency gains for commercial drivers. • The greater drivers' perceived satisfaction, the higher their perceived efficiency. • Electric vehicles' automatic gearbox seems to be relevant to commercial drivers. • Usage anxiety, intrafirm image, age, and usage duration not found relevant. By conducting a cross-sectional survey at Deutsche Post, a major German postal delivery service provider, we examine to what extent commercial drivers accept the substitution of conventional cars with light-duty e-vehicles (LDEVs). Specifically, we explore drivers' acceptance from two perspectives. First, we investigate drivers' perceived satisfaction with LDEVs compared to conventional vehicles. Second, we question whether electric cars in general increase drivers' perceived efficiency of them. Combining these two perspectives, we show that the greater the drivers' overall perceived satisfaction with LDEVs is, the higher is the drivers' perceived efficiency of LDEVs. We prove this by means of perceived usefulness (perceived relative advantage) and perceived ease of use (the opposite of perceived complexity) of LDEVs, using adaptations of Davis' Technology Acceptance Model and Rogers' Diffusion of Innovations Theory to form our Unified Technology Acceptance Model (UTAM). Our findings suggest that, on average, drivers are slightly more satisfied with the LDEVs than with the available conventional cars (n = 66). If drivers were able to choose their preferred vehicles, the majority of them would favor LDEVs. We detect statistically significant patterns of latent measures affecting perceived usefulness and perceived ease of use of LDEVs. Although this paper focuses on German delivery service employees, the methodology presented here could easily be applied to any other enterprise in the growing logistics segment which plans to electrify its car fleet. Hence, our contributions are valuable for transportation research and, more specifically, to all potential commercial EV drivers, e.g., our insights might be relevant for the approx. 500,400 drivers employed in the German logistics sector alone. [ABSTRACT FROM AUTHOR]

Highlights • We analyze the effectiveness of support schemes for micro fuel cells in Germany. • Focus on polymer electrolyte membrane fuel cells (PEMFCs) for private households. • Battery storage and latest market conditions taken into consideration. • The hourly simulation and investment decision model is shown to offer new insights. • The combination of PEMFC and battery storage is found not to be economically viable. Abstract In this paper, the effectiveness of support schemes for micro fuel cells in Germany is analyzed with regard to the latest market conditions, technical characteristics, and legislative changes. To this end, a dynamic model is used and applied to high-resolution household demand data. Specifically, we scrutinize whether polymer electrolyte membrane fuel cells are now a feasible investment option for residential usage in Germany or are likely to become so soon. Furthermore, we investigate whether electric energy storage could be a useful extension to the domestic fuel cell system by supplying short-term peak demand, and thus increasing self-consumption and potentially the overall economic merit. We find that the fuel cell technology analyzed is unlikely to become cost-competitive by 2020, and it may take quite some time to achieve a substantial market diffusion. We conclude that for the time being, electric energy storage in combination with a fuel cell system is not a worthwhile investment in a scenario where grid connection is assumed. [ABSTRACT FROM AUTHOR]

Highlights • A new option-based tool for power plant investment decision-making is introduced. • Study of flexibility options for improved profitability of coal-fired power plants. • Application of a real options approach for the valuation of flexibility options. • Subsidies are still crucial for a profitable operation of lignite plants in Germany. Abstract In this paper the authors develop a decision tool that is based on real options analysis and that supports flexibility investment decisions concerning upgrades of conventional lignite-fired power plants. The value of the power plant is influenced both by technical and economic variables, the latter including subsidies. The four-step approach proposed allows to determine the optimal operation strategy in light of electricity and fuel price developments, to simulate the expected project value, to determine the expected changes of the project value over time, and finally to derive the optimal management (investment/disinvestment) decision. For the case of an existing lignite-fired power plant in Germany, we find that the plant can only be operated profitably without any modifications until the end of its technical lifetime if current government subsidies persist. In the absence of subsidies, however, it is preferable to stop operation immediately. The analysis also shows that profitable investments in a number of flexibility retrofit measures are possible, the ranking of which depends, however, on the costs and benefits related to the retrofitting measures, as well as their implementation time. [ABSTRACT FROM AUTHOR]

In Germany, policy-induced energy efficiency improvements typically aim at reducing primary energy consumption. Private households, on the contrary, pursue the maximization of wellbeing or, in microeconomics jargon, the maximization of utility of the occupants. There is a marked difference between upfront-calculated energy performance ratings (EPRs) and actual heat energy consumption (HEC). From an energy and environmental policy point of view, deviations of energy consumption from ex ante calculated EPRs is problematic, as it jeopardizes their usefulness for (prospective) homeowners, policy-makers and researchers relying on EPRs as a guidance. The EPR-HEC gaps reported are, apart from deviations from the mean aggregate values (i.e. heterogeneity), often attributed to anticipated or unanticipated behavioral effects. From an energy economist's point of view, energy rebound induced by lowered costs per unit of energy service due to increased energy efficiency is one explanation. The related literature almost entirely treats building-specific EPRs as universal standards, trying to explain the empirically observed discrepancies. In this paper, we investigate to what extent the current EPR scheme in place in Germany today can address behavioral issues. To this end, based on two different multi-family housing data sets for Germany and regression analysis, we empirically investigate the deviations between EPRs used in the regulatory norms and the HEC levels observed in reality. We find evidence that it is not necessarily the behavioral dimension, but rather the static and mostly technically guided calculation of the EPRs itself that accounts for the major part of the deviations. We conclude that there is indeed a need for further improvements in the field of EPR regulation and methodology. [ABSTRACT FROM AUTHOR]

We propose an assessment framework for the user experience at public electric vehicle charging stations in Germany, which enables a structured analysis from a driver's perspective. The assessment criteria were derived from 20 interviews with battery electric vehicle drivers and corroborated by existing literature. Seven criteria are considered as particularly relevant: ease of use , green power , comfort , functionality , price , price transparency , and availability. Using Saaty's Analytic Hierarchy Process approach, the weights assigned to these criteria were determined in an online survey with 108 drivers of battery electric vehicles. The results indicate the particular importance of availability and functionality. The assessment framework includes value scores that indicate the match between specific charging stations and the assessment criteria. The conceptual framework can help to support operators of public charging points and electric mobility providers in the design of their services and products, as well as guide policy-makers. [ABSTRACT FROM AUTHOR]

This study investigates the roles of environmental concern and comfort expectations in the decision to retrofit a dwelling and the implications of these two aspects for the rebound effect. We ex-ante elicit individual preferences for deep thermal energy-saving measures in residential buildings by means of a Discrete Choice Experiment (DCE) among 3161 owner-occupiers and tenants in Germany. Besides room temperature, we include air quality, level of control over the system, noise reduction, and aesthetics of the dwelling as proxies for indoor comfort. Our model also accounts for monthly payments related to the implementation of the measure – and customized based on tenancy status, building type, and size of the dwelling – as well as technical energy cost savings. Econometric estimation provides significant results for most of the parameter coefficients. Findings show that thermal comfort preferences are heterogeneous: 33% of the respondents attach positive values to an increase in indoor temperature that would result from the deep retrofit, providing evidence in favor of a technical rebound effect. While environmental concern explains heterogeneity in most of the attributes, its interaction with thermal comfort is not significant. Thermal comfort turns out to be, however, the least important attribute in the analysis while air quality is the most important one. [ABSTRACT FROM AUTHOR]

We propose a generic model which allows to evaluate the economic viability of alternative maintenance strategies for differently sized photovoltaic plants with variable components. We thoroughly review the existing literature on reliability, maintenance and maintenance strategies for PV plants. The model is applied to fixed-tilt ground-mounted solar PV plants in Germany of three different sizes: 1, 10, and 100 MW p . The PV plants are set up in a central inverter configuration with the following components: AC/DC switch, circuit breaker, and inverter. The analysis compares immediate corrective maintenance with maintenance strategies of different periodicity (weekly, bi-weekly, and monthly). Simulations take the driving time of the service team and the operation of a spare parts inventory into account. We further analyze the impact of hourly spot prices in contrast to constant prices (feed-in tariffs). We find that corrective maintenance is the most cost-efficient strategy. If the service journey takes six hours instead of one hour, corrective maintenance becomes more expensive than weekly periodic maintenance. For a three-hour journey, the size of the PV plant matters. If corrective maintenance is adopted, the establishing of a spare parts inventory should be considered. When volatile hourly spot prices are considered, we find that opportunity costs are lowest (highest) when service teams operate at 8 pm (8 am), irrespective of the day of the week, whereas maintenance events scheduled for Wednesdays at 8 am or 2 pm are, given current EPEX spot prices, the most cost-efficient in terms of total costs. [ABSTRACT FROM AUTHOR]

Wind power in Germany has triggered much debate regarding the impacts on landscape and vista. This paper investigates the impact of wind farms on surrounding property values using a hedonic pricing model in a spatial fixed effects and a locally weighted specification. We find that proximity generally causes negative impacts on the surrounding property values. Thereby, local statistics reveal varying spatial patterns across the study area and provide evidence for visibility effects as being a key driver of negative impacts captured by distance measures. The analysis was performed for a study area in Germany. [ABSTRACT FROM AUTHOR]

Germany is among the leading countries regarding the promotion of renewable energy towards a sustainable energy system transition. In this paper, we investigate the German pilot auction scheme for solar photovoltaics introduced in the Renewable Energies Act 2014 (EEG 2014) that serves as a pilot for the auction-based promotion of the three major large-scale renewable electricity generation technologies (wind, solar, biomass) as of 2017. A strategic bidding model is used to determine the optimal bidding strategy and to determine the resulting project value. We consider pay-as-bid and uniform pricing and single and multiple bids. Moreover, we investigate the impact of investment cost uncertainty. In a sensitivity analysis we show how bid strategy adjustments affect the outcome. Specifically, higher uncertainty regarding the market clearing price increases the project value, as this additional uncertainty can be used to raise the probability of obtaining a higher level of remuneration by an adjusted auction strategy. The first-price auction can generate additional profits by placing a second, higher bid with a low probability of success. Investment cost uncertainty can have either a positive or negative impact on the project value, depending on the auction parameter values chosen. [ABSTRACT FROM AUTHOR]

Positive word-of-mouth communication resulting from the experiences of early adopters is a crucial factor in the uptake and diffusion of low-carbon energy technologies over time. Hence, the goal of this research is to study homeowner satisfaction with respect to residential heating systems (RHS) based on renewable energies. In particular, this paper focuses on the role of attributes of the home, homeowners’ socio-demographic characteristics, RHS-related knowledge, and adoption motivations. For this purpose, we apply a linear regression model on a dataset obtained from a survey among homeowners in Germany ( N = 2135) that had adopted an RHS shortly before the survey was conducted. Moreover, we investigate differences between groups of homeowners by means of t -tests and ANOVA. Our research shows that the fulfilment of the motivations for adopting an RHS are relevant factors explaining satisfaction with newly adopted RHS. In particular, the preference to have an RHS that is compatible with daily habits and routines has a strong impact on satisfaction. Furthermore, we find the degree of RHS-related knowledge relevant as well. Socio-demographic aspects – such as age, university degree, gender or income – are found to be less important. We also find differences between groups of adopters. Specifically, adopters of a gas-fired condensing boiler with solar thermal support or a heat pump are less satisfied than adopters of a wood pellet-fired boiler. We conclude that information and education campaigns on clean energy technologies such as RHS based on renewable energies may have a positive impact on homeowner satisfaction resulting in a positive word-of-mouth recommendation and influenec of others. [ABSTRACT FROM AUTHOR]

Flexible energy assets in private households enable many valuable services in the context of a sustainable energy transition. We introduce a combination of a heuristic model and a linear optimization model for the electricity demand of a single-family household with the option to include an electric vehicle. A hybrid model including a heuristic and a Mixed Integer Liner Optimization (MILP) allows to optimize the stacked value across five distinct use cases: (1) maximization of self-consumption; (2) reduction of load peaks; (3) utilization of flexible electricity prices; (4) provision of frequency control reserve (FCR); and (5) reduction of battery aging. We investigate costs and benefits for each use case and, based on data and legislation for Germany, find that several of these use cases result in cost savings of up to €50 per year. Surprisingly, simultaneous investigation of multiple use cases reveals that some combinations show synergetic effects rather than the expected cannibalizing ones. The insights gained are of special importance in the context of designing business models for the aggregation of distributed flexible energy assets, i.e. by an "Energy Supplier 2.0", with the aim to tap unused flexibility potentials, thus utilizing multiple additional revenue streams. [Display omitted] • Flexible distributed energy resources (DER) are valued for multiple use cases. • The focus is on DER in private households in Germany and five distinct use cases. • A MILP optimization approach for utilizing multiple DER value pools is proposed. • It quantifies the stacked economic value for aggregated flexible energy assets. • Simultaneous operation of multiple use cases is found to offer synergy potentials. [ABSTRACT FROM AUTHOR]

This paper dissects the ways in which policy regime risks influence decisions over innovative energy technology investments. We apply compound real options methodology to evaluate the investment in a virtual power plant platform and distributed energy resource (DER) assets in view of volatile electricity market prices and an uncertain future electricity market design. The analysis reveals two aspects of policy regime risks: a policy content effect relating to actual market dynamics resulting from a (new) policy regime, and a policy process effect relating to (uncertainty about) the speed and probability of a regime change. The paper underlines the importance of predictable policymaking to stimulate risky investment. It further details the need to account for technology-specific investment responses to different policy regimes and risks, caused by different degrees of market versus subsidy exposure and differences between platform versus non-platform technologies. [ABSTRACT FROM AUTHOR]

The article introduces various papers published within the issue, including one the market design for long-distance trade in renewable electricity, another on regulatory options for local reserve energy markets and a paper on the impact of the integration of renewable energy sources into the Ontario electricity system.

While the share of fluctuating renewable energy resources is constantly increasing, the centralized, hierarchical organization of the current energy system and markets cannot adequately accommodate such decentralized electricity generation. New ideas have been developed and discussed for improved integration, also in Germany, one of the lead markets. Examples in this context are virtual power plants and microgrids. This paper presents a new local reserve energy market design (applied to residential households), which can facilitate the operation and allow trading within these constructs. Emphasis is put on the regulatory options and current market framework, mainly from a European and a German perspective, which serve as a basis for implementing the local market. It can be shown that using existing regulatory structures, a local market with simple rules (comparable to an "energy-eBay") can be easily installed. [ABSTRACT FROM AUTHOR]

In the light of European energy efficiency and clean air regulations, as well as an ambitious electric mobility goal of the German government, we examine consumer preferences for alternative fuel vehicles (AFVs) based on a Germany-wide discrete choice experiment among 711 potential car buyers. We estimate consumers’ willingness-to-pay and compensating variation (CV) for improvements in vehicle attributes, also taking taste differences in the population into account by applying a latent class model with 6 distinct consumer segments. Our results indicate that about 1/3 of the consumers are oriented towards at least one AFV option, with almost half of them being AFV-affine, showing a high probability of choosing AFVs despite their current shortcomings. Our results suggest that German car buyers’ willingness-to-pay for improvements of the various vehicle attributes varies considerably across consumer groups and that the vehicle features have to meet some minimum requirements for considering AFVs. The CV values show that decision-makers in the administration and industry should focus on the most promising consumer group of ‘AFV aficionados’ and their needs. It also shows that some vehicle attribute improvements could increase the demand for AFVs cost-effectively, and that consumers would accept surcharges for some vehicle attributes at a level which could enable their private provision and economic operation (e.g. fast-charging infrastructure). Improvement of other attributes will need governmental subsidies to compensate for insufficient consumer valuation (e.g. battery capacity). [ABSTRACT FROM AUTHOR]

The Indian power sector is experiencing a lot of pressure to supply sustainable electricity at affordable cost due to heavy demand especially in the summer peak season. Most of India's electricity is produced by fossil fueled power plants, which are the source of CO 2 emissions. In this case, renewable energy sources play a vital role in securing sustainable energy without environmental emissions. This paper examines the effects of renewable energy use in electricity supply systems and estimates the CO 2 emissions by developing various scenarios under the least cost approach. The LEAP energy model is used to develop these scenarios. The results show that in a ARET (accelerated renewable energy technology) scenario, 23% of electricity is generated by renewables only, and 74% of CO 2 reduction is possible by 2050. If the maximum energy savings potential is combined with the ARET scenario, the renewables share in electricity supply rises to 36% as compared to the reference scenario, while the CO 2 emission reduction in this case remains at 74%. [ABSTRACT FROM AUTHOR]

We study the economic viability and optimal sizing and siting of a hybrid plant that combines a ringwall hydro storage system with wind and solar power plants (ringwall storage hybrid power plant, RSHPP). A real options model is introduced to analyze the economics of an onshore RSHPP, and in particular of the varying storage volume in light of the stochastic character of wind and solar power, as well as the optimal investment timing under uncertainty. In fact, many uncertainties arise in such a project. Energy production is determined by the stochastic character of wind and solar power, and affects the optimal size of the storage device. Monte Carlo simulation is performed to analyze the following sources of uncertainty: (i) wind intensity and solar irradiation; (ii) future electricity price; and (iii) investment costs. The results yield the optimal size of the storage device; the energy market on which the operator should sell the electricity generated; numerical examples for two different RSHPP scenarios; and a real options model for analyzing the opportunity to defer the project investment and thus to exploit the value of waiting. [ABSTRACT FROM AUTHOR]

This paper investigates the economic feasibility of power-to-gas (P2G) systems and gas storage options for both hydrogen and renewable methane. The study is based on a techno-economic model in which the net present value (NPV) method and Monte Carlo simulation of risks and price forward curves for the electricity and the gas market are used. We study three investment cases: a Base Case where the gas is directly sold in the market, a Storage & Arbitrage Case where temporal arbitrage opportunities between the electricity and the gas market are exploited, and a Storage & Balancing Case where the balancing markets (secondary reserve market for electricity, external balancing market for natural gas) are addressed. The optimal type and size of different centralized and decentralized storage facilities are determined and compared with each other. In a detailed sensitivity and cost analysis, we identify the key factors which could potentially improve the economic viability of the technological concepts assessed. We find that the P2G system used for bridging the balancing markets for power and gas cannot be operated profitably. For both, temporal arbitrage and balancing energy, pipe storage is preferred. Relatively high feed-in tariffs (100 € MW −1 for hydrogen, 130 € MW −1 for methane) are required to render pipe storage for P2G economically viable. [ABSTRACT FROM AUTHOR]

In this paper, we investigate the economic viability of hydrogen storage for excess electricity produced in wind power plants. For the analysis, we define two scenarios (50 MW system with and without re-electrification unit) and apply Monte Carlo simulation and real options analysis (ROA) to compute hourly profits under uncertainty regarding wind speed, spot market electricity prices, and call of minute reserve capacity. Hydrogen as a storage medium helps to either (1) increase capacity utilization of the wind park in case of grid disconnection; (2) to offer minute reserve; or (3) to exploit temporal price arbitrage at the electricity spot market; additionally, hydrogen can also be directly sold as a commodity. We find that power-to-power operation is highly uneconomical under current framework conditions in Germany, irrespective of potential energy efficiency gains. Interestingly, due to counterbalancing effects, offshore wind parks are found to have only a modest economic advantage compared to onshore ones. The power-to-fuel plant can be operated profitably (at hydrogen prices of more than 0.36 € m −3 and a 100 % utilization of the electrolyzer) if hydrogen is directly marketed instead of used to store and re-generate electrical energy. The ROA recommends investment in a storage device without re-electrification unit beyond an expected project value that is about twice the investment cost of the storage device, a figure which is reduced markedly as conversion efficiency rises, assuming technical change to come at no cost for the investor, i.e. as being exogenous. [ABSTRACT FROM AUTHOR]

This paper analyzes the potential demand for privately used alternative fuel vehicles using German stated preference discrete choice data. By applying a mixed logit model, we find that the most sensitive group for the adoption of alternative fuel vehicles embraces younger, well-educated, and environmentally aware car buyers, who have the possibility to plug-in their car at home, and undertake numerous urban trips. Moreover, many households are willing to pay considerable amounts for greater fuel economy and emission reduction, improved driving range and charging infrastructure, as well as for enjoying vehicle tax exemptions and free parking or bus lane access. The scenario results suggest that conventional vehicles will maintain their dominance in the market. Finally, an increase in the battery electric vehicles’ range to a level comparable with all other vehicles has the same impact as a multiple measures policy intervention package. [ABSTRACT FROM AUTHOR]

• A large-scale energy market model based on a system dynamics approach is proposed. • The model is used to integrate the socio-technical dimensions of the energy system. • There are synergies between the renewable energy mix and carbon capture technology. • Two-factor learning effects do not increase system flexibility in the longer run. • Enhanced flexibility of the market can be ensured without any governmental support. The fundamental energy transition from a fossil-fuel-based energy system towards clean energy is not only about technological change but also about social-technical transition. Using a system dynamics model that includes socio-technical factors and a novel flexibility scoring concept, this paper studies the role of flexibility sources in the European electricity market. Additionally, with the help of the long-term and large-scale electricity market model HECTOR, the study assesses the interplay between the learning rate of a new technology (i.e. carbon capture and storage with flexible sequestration) and the system's flexibility that will be enhanced by the diffusion of the new flexible technology. Furthermore, the impact of the renewable energy mix on the electricity market's flexibility is studied by considering the dominance of a specific renewable energy technology (offshore and onshore wind) in the electricity market. The simulation results show that the system's flexibility can reach higher levels by 2050 if socio-technical parameters are included in HECTOR. A comparison of offshore and onshore wind-oriented scenarios highlights that in the offshore wind-oriented scenario, 3.43 TWh less renewable electricity is generated than in the onshore wind-oriented scenario, and that 16.2 Gigatons more of CO 2 are emitted than in the onshore wind-oriented scenario. Overall, it can be concluded that, in the long term, offshore wind provides 9 % higher flexibility to the system than onshore wind does. [ABSTRACT FROM AUTHOR]

Abstract: Biomass cofiring in coal power plants (with thermal contributions of typically 5–20%) is an interesting option to mitigate CO2 emissions, since the additional costs are relatively minor and a secondary benefit is provided by the increased fuel flexibility. Worldwide, about 150 cofiring plants are in operation. In Germany, the electrical power potential for biomass cofiring in coal plants is about 28 TWh per annum, assuming a 10% replacement of coal combustion by biomass. In this paper, we study the economic potential of biomass cofiring in hard coal power plants in Germany. To this end, we identify suitable biomass input fuels, investment and operating costs, and the profitability of cofiring investments. In a sensitivity analysis, we check for the robustness of the results gained, and in a Monte Carlo simulation (MCS) uncertainties are explicitly taken into account. We find that both regional and international biomass supplies are relevant, and that the cost effectiveness of cofiring is strongly affected by the prices for biomass, coal and CO2 permits, while investment and operating costs only have a modest influence. According to our calculations, electrical power generation costs attributable to biomass combustion for a plant put into operation in 2020 are between 70 and 75 € MWh−1, while the average costs of biomass fuel from various sources and markets are calculated to be around 4.1 € GJ−1. [Copyright &y& Elsevier]

Abstract: In this paper we investigate the value of capture-readiness by modeling the cost effectiveness of various alternative technological options and focusing on different clean-coal technology pathways. The modeling framework developed is based on stochastic net present value calculations. It allows for consideration of path-dependent and technology-specific risk combinations inherent in the input and output commodities that are relevant for operating the plant. We find that capture-readiness competes with alternative options of power plant replacements and that capture-readiness is not necessarily preferable from an economic perspective. [Copyright &y& Elsevier]

Abstract: In this paper we model the economic feasibility of compressed air energy storage (CAES) to improve wind power integration by means of a profit-maximizing algorithm. The Base Case is a wind park with 100MW of installed capacity and no storage facility. In Variant 1 we add a central CAES system with 90MW of compressor and 180MW of generation capacity. The compressed air is stored in a cavern. The CAES system is operated independently of the wind park such that profits from peak power sales on the spot market and the reserve power market are maximized. Variant 2 is an integrated, decentralized CAES system, where each wind turbine is equipped with a compressor but no generator. The compressed air is stored in a cavern and converted into electricity by a turbine, again maximizing profit as a peak power plant. Both variants are modeled for conventional diabatic and the more advanced adiabatic systems. We find that the economics of the systems studied depend on how intensively the spot market and the market for minute reserve are used. Unless a minute reserve market exists, where hourly contracts can be traded, none of the CAES power plants studied is economically feasible. CAES plants can be operated economically if combined trade in the spot market and the minute market is enabled, and provided that some support scheme is in place (e.g., such as the German Renewable Energies Act). A centralized CAES plant is found to be more attractive than a wind power plant with integrated CAES, irrespective of whether a feed-in tariff scheme also exists for the integrated plants. Diabatic CAES turns out to be more profitable than adiabatic CAES. [Copyright &y& Elsevier]

Abstract: This paper investigates whether coal-fired Integrated Gasification Combined-Cycle (IGCC) power plants can be an economically viable future technology for providing less carbon-intensive electricity and heat energy in Germany than today. In the context of CO2 emission mitigation in power generation, energy conversion technologies enabling the implementation of Carbon Capture and Storage (CCS) need to be considered. IGCC is such a technology, as it utilizes coal but does not necessarily emit CO2. In our study we investigate, from an economic perspective, whether IGCC plants can be an alternative to nuclear and/or conventional coal-fired power plants. The research is based on scenario analysis. The starting point is the expected shut-down of nuclear power stations and outdated coal-fired power plants, as well as the projected evolution of the CO2 price. The hot gas cleaning option in IGCC plants is of particular interest, as it allows a significant enhancement of the efficiency of the IGCC technology and the use of combined heat and power production (CHP). Corresponding supplementary earnings (incl. subsidies) are compared with an increase in specific investment costs. Besides hot gas cleaning, we also investigate the economic impact of injecting pure CO2 (separated from the IGCC process) into oilfields, as Enhanced Oil Recovery (EOR) can help to reduce the costs of CO2 transport and storage. Based on the results from our analysis we find that the replacement of currently operating power plants by IGCC facilities is only reasonable under certain circumstances, e.g. for locational reasons. Furthermore, from today’s perspective, and due to its various advantages, a complete abandonment of the IGCC technology seems rather unlikely. Our analysis of NPVs of total costs indicates that some IGCC designs exist that are less expensive to set up and operate than a conventional reference power plant. The option of injecting CO2 sequestered from the power plant process into almost depleted oil fields appears attractive for a utility investing in IGCC technology, rendering such a plant configuration as likely cost-competitive. However, with regard to climate change mitigation, the least-cost investment alternative is not necessarily the one with the lowest GHG emissions. Significant cost reductions can be achieved by improving the efficiency or the availability of the plant. Finally, the NPV changes markedly when the heat-to-power ratio is altered, and high ratios are found to be incompatible with NPV minimization. [Copyright &y& Elsevier]

Abstract: In this paper we study the economic feasibility of constructing a 560MW coal-fired power plant in Turkey, using real options theory . We start from a short review of the Turkish electricity market as well as the literature on real options theory and power plant investment. We then investigate the peculiarities and uncertainties related to large-scale power generation. Our special research focus is on the determination of the real options value of the sequential nature of the power plant project considered. To this end, we develop a sequential investment model based on the binomial tree model of Cox et al. . The four stages considered are (1) initial project development; (2) detailed planning and permitting; (3) first major project payments; and (4) release of final order. We find that especially for the strategic planning of projects the application of the real options analysis (ROA) can be very useful. The relatively high option value compared to the net present value (NPV) of the project makes clear that the flexibilities of reacting during project realization, depending on the market developments, can be assigned a substantial value. A further advantage of the ROA for a staged or sequential investment lies in the fact that it also delivers, besides the option value of the investment, the optimal strategy for exercising the option (i.e. if and when to invest). The revelation of action possibilities and their examination sheds new light on the conventional calculation of the NPV of such projects. [Copyright &y& Elsevier]

Abstract: In this study, a techno-economic evaluation method for the energy retrofit of buildings is introduced, geared toward finding the economically optimal set of retrofit measures. Split incentives of building owners and users are considered explicitly in a conventional (static) evaluation to identify the investment alternatives maximizing the net present value (NPV). Energy price uncertainty for various distributional assumptions of the stochastic variables is addressed through Monte Carlo simulation. Results from the simulation are used to compute probabilities and expected NPVs. Based on this, a sequential (dynamic) evaluation method is developed, featuring a real options investment appraisal. The real options approach is introduced as an advancement in the practice of economic evaluation of building retrofit investment options. The new method is applied to an office building in Germany, illustrating its performance. The case study results indicate that energy price changes significantly affect the profitability of retrofit investments, and that high price volatility creates a substantial value of waiting, making it more rational to postpone the investment. [Copyright &y& Elsevier]

Abstract: The economics of large-scale combined heat and power (CHP) generation for district heating (DH) applications are strongly affected by the costs and allocation mechanism of CO2 emission allowances. In the next period of the European emissions trading system (EU ETS), from 2013 onwards, the allocation rules for CHP generation will be modified according to the principles announced in EU Directive 2009/29/EC. In this paper, we analyze the impact of the intended modifications on large-scale coal- and gas-fired CHP plants for DH in Germany. By means of a discounted cash-flow model we first show that the implementation of the modified allocation mechanism significantly reduces the expected net present value of the technologies considered. In a next step, by applying a spread-based real options model, we analyze the decision-making problem of an investor who intends to invest in CHP generation. Our results provide some evidence that the modified EU ETS principles contribute to reducing the attractiveness of investments in large-scale CHP plants that feed into DH systems. If these effects are not compensated, this could lead to a situation where highly efficient CHP plants are gradually replaced by separate power and heat generation in boilers respectively fossil-fueled condensing plants. [Copyright &y& Elsevier]

Abstract: The Integrated Energy and Climate Protection Program of the German government includes the political target of doubling the share of combined heat and power generation (CHP) in Germany from currently about 13% to 25% by 2020. In order to reach this goal, a new CHP law was enacted to improve the framework conditions for CHP generation. In this paper, we aim at identifying which CHP technologies are most likely to be installed in the near future to reach the CHP target stipulated by the German government. In our model, we apply Mean-Variance Portfolio (MVP) theory to consider return- and risk-related aspects of various CHP technologies. The analysis pays tribute to specific characteristics of CHP generation, such as promotion via guaranteed feed-in tariffs, additional revenues from heat sales, specific operational features, and specifics concerning the allocation of CO2 allowances. The investigation is based on four generic standard CHP technologies currently available on a commercial basis: large coal-fired CHP plants, combined-cycle gas turbines (CCGT-CHP), engine-CHP and micro-turbine CHP. As selection criteria for the portfolio performance we take, independently from each other, the net present value (NPV) of investment in CHP and the expected annual portfolio return, and compare the results obtained from both approaches. Irrespective of the chosen selection criteria, the analysis shows that CCGT-CHP and engine-CHP are the most attractive CHP technologies from a return perspective. A diversification of the portfolio with other kinds of CHP technologies can contribute to stabilizing portfolio returns. In view of the results obtained we conclude for the further development of CHP generation in Germany that a large portion of additional new CHP capacity will probably be built in the industrial sector. [Copyright &y& Elsevier]

Abstract: In this paper, we investigate the development and economic potential of the photobioreactor (PBR) technology for energy purposes, i.e. production of hydrogen or biofuels. The approach adopted is to consider the technology, its expected costs and revenues, and related risks from an investor perspective. To this end we develop an investment model that is used to calculate the economic feasibility of PBRs for different scenarios, including a best-case scenario, with plenty of sunlight and water, inexpensive nutrients, high prices for hydrogen and biomass, and low other costs. The best-case scenario is compared to a scenario with less favorable boundary conditions. We find that PBR efficiencies will likely be less than 10%, with typical values between 1.8% and 5.6%. We also find that hydrogen production costs would be lower than those for biodiesel or biogas from solid biomass produced in PBRs. Compared to biofuels from traditional agriculture there is a great advantage for the PBR technology if land is scarce, because land is used more efficiently. Since PBRs can be designed as a closed system they can be applied in very dry regions. In the long term this might enable this promising concept to penetrate the energy supply market. [Copyright &y& Elsevier]

With the expansion of distributed energy resources and the phaseout of the feed-in-tariff scheme in Germany, self-consumption and electricity sharing within a community of prosumers are becoming more profitable. This paper derives optimal business models for a sustainable peer-to-peer (P2P) energy trading platform (ETP) in Germany. It examines data from 1618 residential households collected from an online survey, including 1311 consumers and 307 prosumers. Our research aims to better understand under what circumstances these households would participate in a P2P ETP and how business models can support such platforms to create added value for private households. Therefore, households' beliefs concerning their attitudes, perceived behavioral control, and subjective norms are analyzed according to the Theory of Planned Behavior, and business models are designed correspondingly. In order to evaluate the developed business models' effectiveness and usefulness, we apply them to fifteen existing pioneer energy communities and platforms in Germany. We find that cost-saving and other financial benefits for households must be considered to be the primary value proposition offered by a service provider. Business models which help households to become more electricity self-sufficient and to consume less electricity from the public grid are the second-most important source of value creation from a household's point of view. By connecting the business models and the P2P prosuming market model, recommendations for companies, policy-makers, and regulatory authorities are made. • Households decide to become prosumers due to cost savings and financial benefits. • A suite of business models for future energy service providers is suggested. • Business models increase households' financial benefits and save on energy costs. • Business models proposed enable households to increase energy self-sufficiency. • Companies should focus more on creating P2P energy-sharing communities or platforms. [ABSTRACT FROM AUTHOR]

Abstract: The municipal utilities of Basel (IWB) are in the process of building a 30MW wood-fired cogeneration plant in the city of Basel, Switzerland, a project idea that was initially proposed by visionaries from the forest sector. Despite recent doubts about its profitability due to unforeseen major increases in investment costs, the plant is attractive both politically and from a business perspective, as several goals related to the increased use of renewable energy can be achieved simultaneously. Moreover, significant woody biomass resources are awaiting further exploitation in the Basel region, which could help to improve markedly the cost effectiveness of forest maintenance. In this paper, we study the history and some of the characteristics of the project from a socio-economic perspective. Of particular interest to our study is the early involvement of a large number of stakeholders with different interests. The project constitutes a pioneering project that could serve as an important non-Scandinavian model for similar projects in other parts of Switzerland, but also in Western and Central Europe as a whole. The lengthy decision-making and planning process offers interesting insights into the socio-economic drivers and barriers of large-scale bioenergy projects in urban settings, where wood heating systems are in general not as well established as in the countryside. We find that the interest of regional forest owners to tackle the problem of over-aged and largely unprofitable forests, coupled with a political climate that (1) favours green energy projects and (2) provides incentives for the municipal utility to produce more green energy from sources other than hydropower, have been the two main success factors for developing this particular biomass plant project. [Copyright &y& Elsevier]

Abstract: In recent years, the threat of global climate change, high fuel import dependence, and rapidly rising electricity demand levels have intensified the quest for more sustainable energy systems. This in turn has increased the need for policy makers to promote electricity generation from renewable energy sources. Guaranteed prices coupled with a buy-back obligation for electricity fed into the grid is a popular renewables promotion instrument, especially in Europe. More recently, driven mainly by electricity market liberalisation efforts, quota targets for the share of renewables in combination with tradable ‘green’ certificates (TGC) have received considerable attention. TGC offer a greater theoretical potential for economic efficiency gains, due to price competition and the greater flexibility assigned to the obliged parties. While guaranteed prices and TGC schemes support the operation of renewable energy technology systems, bidding schemes for renewable energy generation capacity are used to raise economic efficiency on the plant construction side. All of these policy instruments suffer from the shortcoming that they do not explicitly account for the often widely varying environmental, social and economic impacts of the technologies concerned. In this paper, we propose a methodology for the design of renewable energy policy instruments that is based on integrated assessment. In particular, we argue that using participatory multicriteria evaluation as part of the design of renewable energy promotion policies would make it possible: (1) to differentiate the level of promotion in a systematic and transparent manner according to their socio-ecological economic impact, and (2) to explicitly account for the preferences of stakeholders. A further problem of existing TGC and bidding schemes is that diversity of supply could be severely diminished, if few low-cost technologies were allowed to dominate the renewable energy market. To ensure a certain diversity of technologies, our scheme suggests the use of different technology bands for technologies that are relatively homogeneous with respect to their maturity. [Copyright &y& Elsevier]

In this study, we compare and contrast the impact of recent technological developments in large biomass-fired and natural-gas-fired cogeneration and condensing plants in terms of CO2 mitigation costs and under the conditions of a competitive electricity market. The CO2 mitigation cost indicates the minimum economic incentive required (e.g. in the form of a carbon tax) to equal the cost of a less carbon extensive system with the cost of a reference system. The results show that CO2 mitigation costs are lower for biomass systems than for natural gas systems with decarbonization. However, in liberalized energy markets and given the socio-political will to implement carbon extensive energy systems, market-based policy measures are still required to make biomass and decarbonization options competitive and thus help them to penetrate the market. This cost of cogeneration plants, however, depends on the evaluation method used. If we account for the limitation of heat sinks by expanding the reference entity to include both heat and power, as is typically recommended in life-cycle analysis, then the biomass-based gasification combined cycle (BIG/CC) technology turns out to be less expensive and to exhibit lower CO2 mitigation costs than biomass-fired steam turbine plants. However, a heat credit granted to cogeneration systems that is based on avoided cost of separate heat production, puts the steam turbine technology despite its lower system efficiency at an advantage. In contrast, when a crediting method based on avoided electricity production in natural-gas-fired condensing plants is employed, the BIG/CC technology turns out to be more cost-competitive than the steam turbine technology for carbon tax levels beyond about $ 150/t C. Furthermore, steam turbine plants are able to compete with natural-gas-fired cogeneration plants at carbon tax levels higher than about $ 90/t C. [Copyright &y& Elsevier]

This paper shows how bottom-up activity analyses within a dynamic computable general equilibrium framework can be undertaken for the longer-term analysis of energy and climate policies using the model SCREEN [25]. In particular we demonstrate for the case of Switzerland how the impact of policy measures to reduce the carbon intensity of the energy sector can be assessed with such a model for various socio-economic and environmental dimensions (e.g., C02 emissions, GDP, employment, foreign exchange rate). The results can provide valuable insights for the appropriate design of energy or climate policies that allow for the targeted fostering of a more sustainable energy development. [ABSTRACT FROM AUTHOR]

In this paper, we investigate the potentials of distributed generation (DG) in a medium-sized Swiss city. We show the role of private households in the sustainable energy transition process induced by Swiss energy policy. For the analysis, we define six scenarios that enable us to study the potentials and impacts of different combinations of DG technologies in terms of costs, CO2 emissions, and amounts and shares of DG provided by non-industrial end-users (essentially private households and the services sector). Three variants are investigated, one with real electricity costs and CO2 emissions, one with increased electricity costs (e.g., construction of new power plants), and one with increased CO2 emissions (e.g., due to the planned nuclear phase-out in Switzerland). We find that non-industrial entities can play an important role as prosumers. They mitigate the need for centralized generation. Within a scenario where the non-industrial energy end-users install water-water heat pumps and photovoltaics, a total reduction of the gas procurement from the grid is possible whereas the electricity demand from the grid increases by 24%. This scenario reveals higher DG electricity costs in comparison to conventional electricity supply, but the total costs of energy supply decrease due to the elimination of gas supply, and the CO2 emissions can be reduced by 68%. [ABSTRACT FROM AUTHOR]

In this paper, we evaluate selected multi-business utilities in the European energy market with regard to synergy potentials. To this end, we survey the development of the energy market in Europe and the performance of integrated versus focused utilities regarding their capital market performance measured by their corporate surplus (or deficit). The analysis is restricted to true business integration, in contrast to horizontal or vertical cooperation among separate firms. The German utility company RWE is analyzed in more detail. We find that, over the last 10–15 years, most of the multi-business utilities investigated underperformed compared to more focused utilities, and that they were even below the STOXX Europe 600 utilities index. Furthermore, synergy potentials need to be evaluated continuously, especially when influencing factors, with the potential to act as "game changers", are either emerging on the horizon or are already present. We conclude that operating an integrated business model is not necessarily outdated in today's energy markets, and offers a number of advantages. [ABSTRACT FROM AUTHOR]

This study researches the concept of underground pumped-storage hydro power plants in closed-down underground hard coal mines in Germany. After a review on how this could be realized technically, an economic feasibility analysis is presented, with a particular focus on the costs for the underground storage reservoir. The analysis is performed for different lower (i.e., underground) reservoir sizes and temporal arbitrage potentials (peak/off-peak electricity price spreads), and cost uncertainty is dealt with by means of a Monte Carlo simulation for two distinct head heights. The findings regarding costs and acceptability are compared with those of a classic (on-surface) pumped-storage hydro power plant in a mountainous area. Based on a techno-economic evaluation we conclude that under favorable conditions the realization of underground pumped-storage hydro power (UPSHP) plants seems both technically feasible and economically reasonable. More specifically, an extension of a tubular system seems the most promising option. A UPSHP plant in a mineshaft is probably slightly more expensive than a conventional one, an outcome that depends strongly on the feasible head height. However, the significant reduction of the adverse impacts on the landscape and on local residents, as well as a potentially large number of feasible sites in flat terrain, could make UPSHPs an interesting option for the future energy transition, not just in Germany but worldwide at sites where underground mining is being abandoned. [ABSTRACT FROM AUTHOR]

This work aims at the economic evaluation of a semi-underground pumped hydro storage power plant erected in an abandoned open-pit mine. For the exploratory model-based analysis, we develop and apply both a simple deterministic and a stochastic net present value (NPV) approach, the latter of which uses a Monte Carlo simulation to account for revenue uncertainty from electricity price fluctuations. The analytical framework developed is applied to two promising sites in the Rheinland region in Germany, Hambach and Inden, making reasonable parameter value assumptions and considering and ignoring the lengthy duration of lower reservoir flooding. The investor's value-at-risk is computed for alternative performance indicators (NPV, net cash recovery, profit-to-investment ratio, and specific production costs) to compare the different outcomes in terms of the project's financial risk distribution. Calculations show that a semi-underground pumped hydro storage power plant in an abandoned open-pit mine can be constructed at reasonably low investment costs and operated at low specific production costs. However, because the investment has to be made long before the pit lake is (naturally) flooded—a process that for realistic flow rates may take up to 20 years—the project is highly uneconomical and would require substantial subsidies, as compared to a situation where flooding happens immediately. [ABSTRACT FROM AUTHOR]

In this paper, we investigate capacity expansion, the technological development of wind turbine generators, and the merits of onshore wind repowering in Germany. We analyze the regulatory framework that is presently in place and its impact on the profitability of the onshore wind parks commissioned under previous regulatory frameworks. The optimal timing of repowering under today's market premium model is scrutinized. Repowering in a market without subsidies for onshore wind energy is also evaluated. In the two cases (regimes) investigated, the electricity price is modeled stochastically as a geometric Brownian motion process. More specifically, using a real options modeling framework for investments under a free market regime, we analyze how the regime change affects the optimal timing of repowering. Further, we check the results for their robustness via a sensitivity analysis for both analyzed regimes. We find that repowering well before the plant's expected end of life ('early repowering') can be economically preferable under the German Renewable Energy Sources Act 2017 remuneration scheme and that, due to the electricity spot market price development, repowering under the market premium regime is more profitable than it is under the free market regime. The economic viability is strongly influenced by the duration of the initial tariff granted to the old installation, the expected digression factor of the future reference tariff, and the increase in electricity generation achieved through repowering. [ABSTRACT FROM AUTHOR]

• Gas-fired power plants are often no more profitable under current market situation. • Retrofit measures that enable a more flexible operation can enhance profitability. • A real options model is proposed for the flexibility investment decision-making. • The optimal operation strategy is shown for two hourly profitability indicators. • The retrofit decision depends significantly on some of the economic parameters. The promotion of electricity from renewable energies in Germany causes difficulties in the profitable operation of many modern conventional power plants. Also, fluctuating availability of power from renewable energy sources requires flexible conventional plants, i.e. power plants which are able to react fast to these fluctuations. In this paper, we propose a model which provides some decision support tool for the operators of conventional power plants regarding investments in technical upgrades aimed at enhancing the flexible operation of these power plants. Because of the irreversible character of the investments considered we apply a real options approach to the gas-fired power plant investigated. We compare the electricity price and the spark spread as profitability indicators and sources of uncertainty, and use a simplified 3-stage definition of the power plant's operation strategy. In a case study for a combined cycle gas-fired turbine plant recently built in Germany, we find that the retrofit decisions depend strongly on economic parameters, such as the level of the operation and maintenance costs, as well as the enabled longer operation time on the maximum level. The proposed procedure can help to assess the expected future profitability role of conventional power plants, and supports the decision-making process regarding both reinvestments and optimal operation of power plants in markets with high shares of variable renewables. [ABSTRACT FROM AUTHOR]

This paper aims to analyze what happens with renewable energy power plants, such as onshore wind, photovoltaics and biomass, when the public policy support based on the Renewable Energy Law expires. With its expiration, the first renewable energy (and especially onshore wind) power plants will have to be scrutinized as to whether they can economically continue operation, whether they have to be repowered, or whether they need to be decommissioned. The relative merits of these three alternatives are evaluated by applying real options analysis. In contrast to traditional project evaluation techniques, the real options approach takes advantage of the use of uncertain parameters included in the model, such as the development of the electricity price or electricity output. The results obtained suggest that parameters such as the level of future operation and maintenance costs, the expected development of the electricity price at the spot market, and the interrelations between these, as well as the development of the electricity output from renewables can significantly affect the profitability of these power plants and thus impact the decision about their further optimal operation. [ABSTRACT FROM AUTHOR]

The novelty of large-scale green hydrogen technology with its numerous applications, and the competition with well-entrenched conventional technologies, still makes it difficult to operate renewable power-to-hydrogen (P2H) plants profitably. In this study, sequential investments in the P2H plants are investigated using a Real Options approach. The analysis addresses the question of what the optimal timing is for sequential investments in P2H modules that enable hydrogen feed-in into the gas grid in Germany and California, both pioneers in the sustainable energy transition. Choosing this approach, the uncertain and largely irreversible character of the P2H investments is tackled. Since the focus is on substituting natural gas by adding green hydrogen to the gas grid, the underlying asset considered as stochastic is the price of natural gas. It is modeled by applying a geometric Brownian motion process. The analysis conducted reveals that for both California and Germany polymer electrolyte membrane (PEM) electrolyzer systems are uneconomical in the foreseeable future, at least based on the assumptions made in the case studies. The required natural gas price level that would enable economic viability of gas grid feed-in exceeds the level of today's natural gas prices many times over. Without policy support (e.g., subsidies or quotas for green hydrogen, sufficiently high carbon tax), or an increased willingness to pay for green fuel on the customers' side, it is unlikely that the required minimum hydrogen price level for profitable business will be reached any time soon. [Display omitted] • Optimal timing of sequential investments in hydrogen generation plants is examined. • Investments are considered to be subject to uncertainty and largely irreversible. • Two case studies are analyzed (Germany, California) using Real Options Analysis. • In both cases, electrolyzer systems are found to be uneconomical in the near future. • Subsidies and/or an increased willingness to pay for green fuels are thus required. [ABSTRACT FROM AUTHOR]

Fuzzy theory is proposed as an alternative to the probabilistic approach for assessing portfolios of power plants, in order to capture the complex reality of decision-making processes. This paper presents different fuzzy portfolio selection models, where the rate of returns as well as the investor's aspiration levels of portfolio return and risk are regarded as fuzzy variables. Furthermore, portfolio risk is defined as a downside risk, which is why a semi-mean-absolute deviation portfolio selection model is introduced. Finally, as an illustration, the models presented are applied to a selection of power generation mixes. The efficient portfolio results show that the fuzzy portfolio selection models with different definitions of membership functions as well as the semi-mean-absolute deviation model perform better than the standard mean-variance approach. Moreover, introducing membership functions for the description of investors' aspiration levels for the expected return and risk shows how the knowledge of experts, and investors' subjective opinions, can be better integrated in the decision-making process than with probabilistic approaches. [ABSTRACT FROM AUTHOR]

Short-term forecasting of electricity generation from variable renewable energy sources is not an end in itself but should provide some net benefit to its user. In the case of electricity trading, which is in the focus of this paper, the benefit can be quantified in terms of an improved economic outcome. Although some effort has been made to evaluate and to improve the profitability of electricity forecasts, the understanding of the underlying effects has remained incomplete so far. In this paper, we develop a more comprehensive theoretical framework of the connection between the statistical and the economic properties of day-ahead electricity forecasts. We find that, apart from the accuracy and the bias, which have already been extensively researched, the correlation between the forecast errors and the market price spread determines the economic implications - a phenomenon which we refer to as 'correlation effect'. Our analysis is completed by a case study on solar electricity forecasting in Germany which illustrates the relevance and the limits of both our theoretical framework and the correlation effect. • The economics of short-term electricity forecasts are studied analytically and empirically. • The value and the risk of forecast-based electricity trading are evaluated. • We find that the economics depend on the correlation of forecast errors with prices. • Hence, the most accurate forecast is not necessarily the most accurate. [ABSTRACT FROM AUTHOR]